This invention relates to a formation consolidation process used in subterranean wells. The process comprises injecting into an unconsolidated or loosely consolidated subterranean formation penetrated by a wellbore an aqueous pumpable system containing an insoluble silica source (e.g., colloidal silica or silica fume) and a source of calcium hydroxide (e.g., a mixture of calcium chloride and sodium hydroxide in an aqueous medium). The components of the aqueous pumpable system react to produce a calcium silicate hydrate gel (C-S-H gel) with cementitious properties. The technique can be performed as a remedial treatment or in new completions, but it is particularly useful in workover treatments for existing wells.
Hydrocarbon fluids, such as oil and natural gas, and other desirable formation fluids are obtained from a subterranean geologic formation, i.e., a reservoir, by drilling a well that penetrates the formation zone that contains the desired fluid. Once a wellbore has been drilled, the well must be completed. A well “completion” involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, production of the formation fluids can begin.
When the subterranean formation is “soft” or poorly consolidated, small particulates (typically sand) present in the formation may dislodge and travel along with the produced fluid to the wellbore. Production of sand is highly undesirable since it erodes surface and subterranean equipment, and it must be removed from the produced fluids before they can be processed. In addition, the migrating sand can plug the flow channels in the formation and thereby necessitate other stimulation techniques, such as acid stimulation, to restore the well's performance.
Various methods have been employed to reduce or eliminate the concurrent production of sand and other particulates with the formation fluids. One common approach has been to filter the produced fluids through a gravel pack that has been placed into the wellbore. Such gravel packs are often retained by a metal screen. The produced formation fluids travel through the permeable gravel pack (and the screen) before entering the wellbore. The sand and other particulates in the produced fluids are blocked by the gravel pack. This technique has been widely used in the past, but it has several disadvantages. With time, the gravel pack and the screen may be plugged by scale or particles, or badly eroded by the sand and other particulates in the produced fluids. This reduces the effectiveness of the gravel pack and screen and may actually shut down the production if the gravel pack and/or screen becomes plugged with sand or formation fines. In addition, the presence of the metal screen in the well inhibits reentry of drills and other tools into the wellbore and the metal screen can be difficult and costly to remove.
This helps to explain the industry's desire to develop so-called screenless completion techniques. These techniques typically involve the injection of a consolidating fluid, such as a resin-based consolidating fluid, through the wellbore and into the formation surrounding the interval of interest. Resin-based consolidating fluids generally include an organic resin, a curing agent, a catalyst and an oil wetting agent. The resin system hardens in the formation, thereby consolidating it. Examples of such resin-based consolidating fluids and methods for using them are reported in many patents. See, for example, U.S. Pat. Nos. 4,291,766; 4,427,069; 4,669,543; 5,199,492; and 5,806,593. Resin-based consolidation systems may be complicated to apply, especially those involving multiple treatment stages, and the treatment results may be erratic. When the individual components of the consolidating fluid are pumped at different stages into the formation they may or may not come together in the right order, or in the right amounts, or they may not even come together at all. And, if they do come together, good mixing of the components is not assured. This helps explain the erratic and unreliable results that operators have experienced using such multi-stage consolidating fluids.
In an effort to overcome some of the disadvantages of resin-based consolidation fluids, other well treatments have been proposed which use inorganic systems to modify the formation and thereby reduce the production of formation fines.
For example, U.S. Pat. No. 3,593,796 describes a multi-stage process in which the following components are injected sequentially into the formation: (1) an aqueous solution containing a silicate adapted to wet the fine sand grain particles, (2) an aqueous solution of a silicate-precipitating agent capable of reacting with the silicate in solution (1) so as to form a solidifying material and therein to bind the fine sand grain particles, and (3) a solution containing an oil-wetting agent. This treatment is designed to immobilize the fine particles in the formation and prevent their migration when subjected to subsequent fluid flow. The patent states that aqueous solutions of alkaline earth metal salts (e.g., calcium chloride), acidic iron salts, and certain other metal salts can be used as the silicate-precipitating agent.
In another instance, U.S. Pat. No. 3,741,308 describes a method of converting an unconsolidated sand formation into a consolidated, permeable formation by flowing volumes of aqueous calcium hydroxide (or compounds which hydrolyze or react with each other to form calcium hydroxide) through the pores of the unconsolidated formation. The patent states that the calcium hydroxide solution could be formed by adding sodium hydroxide to a solution of calcium chloride. The patent also states that during the practice of the process the sand particles in the formation become coated with calcium silicates of unknown or indefinite composition, and proposes that the coating cements the individual grains together and increases the structural strength of the sand assemblage.
Yet another approach has been described in two companion cases (U.S. Pat. Nos. 5,088,555 and 5,101,901). In U.S. Pat. No. 5,088,555, a sand consolidation method was described involving sequential injections of (a) an aqueous solution of an alkali metal silicate and (b) certain organic solutions of a calcium salt (e.g., calcium chloride hydrate or chelated calcium) through perforations in the casing of a borehole. The components of these two solutions are said to react to form a calcium silicate cement with permeability retention characteristics in the formation interval being treated that prevents sand from being produced during the production of hydrocarbon fluids from the well. U.S. Pat. No. 5,101,901 describes a method of forming a gravel pack in a washed-out interval adjacent a borehole in an unconsolidated formation using the same sequential injection of the aqueous silicate solution and an alcoholic solution of a calcium salt. These materials react to form a calcium silicate cement, as noted in U.S. Pat. No. 5,088,555, which functions as a gravel pack to eliminate sand and other formation fines from the produced hydrocarbon fluids.
In essentially all multistage consolidation treatments, there is an element of chance in whether the reactants/components will be combined in the formation in the proper order, the proper amounts, or whether they will even come in contact at all in the desired formation interval of interest. The efficiency of mixing/blending is also questionable. But, in some instances the multistage treatments work. For example, U.S. Pat. No. 5,551,514 describes a multi-stage consolidation followed by a hydraulic fracturing treatment in which proppant flowback control techniques are employed. This procedure has been used successfully on many wells.
To avoid the difficulties associated with multi-stage consolidation systems, U.S. Pat. No. 6,450,260 describes an alternative method of performing the technique patented in U.S. Pat. No. 5,551,514, using a single-stage flexible gel system. Following the consolidation step, the formation permeability surrounding the treated interval is too low to allow the practical production of hydrocarbons. Therefore, as illustrated in U.S. Pat. No. 5,551,514, the fracturing treatment is essential to reestablish well productivity.
Other fracturing treatments that help minimize sand production generally involve the step(s) of determining the direction of fracture propagation and then orienting or shaping the perforations to optimize the flow path between the fracture and the wellbore. Such treatments minimize the near-wellbore drawdown pressure during production, and sand production can be prevented. See, for example, U.S. Pat. Nos. 5,386,875; 6,283,214 and 6,431,278.
Though some of the above-mentioned techniques have achieved a degree of commercial success, many of them have been hindered by technical and/or cost limitations.
It is therefore an object of embodiments of the present invention to provide a single-stage formation consolidation process that can be used in subterranean wells. Like U.S. Pat. No. 6,450,260, it is also an object of the present invention to render the consolidated zone of the formation impermeable, or essentially impermeable, to the flow of formation fluids. After the consolidation treatment, hydraulic fracturing optionally coupled with proppant flowback control is performed to optimize communication with the productive formation and prevent sand production.
It is another object of embodiments of the present invention to provide a screenless completion process for completing an unconsolidated interval and preventing or substantially reducing the concurrent production of sand and other particulates with the formation fluids.
These and other objects are achieved by embodiments of the invention set forth below.